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Good day, ladies and gentlemen, and welcome to the Third Quarter 2018 Hess Corporation Conference Call. My name is Gigi and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Thank you. Good morning everyone and thank you for participating in our third quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.
Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risk and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC. Also, on today's conference call we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
Now, as usual, with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.
Thank you, Jay. Welcome to our third quarter conference call. I will provide a strategy update, Greg Hill will then discuss our operating performance, and John Rielly will review our financial results.
We delivered another strong quarter of execution with higher production and guidance and lower unit costs and guidance while keeping capital and exploratory expenditures flat with guidance for the year and generating a profit for the quarter. We continue to execute our strategy to deliver capital-efficient growth in our resources and production, investing in the highest return projects to move down the cost curve and be profitable in a lower price environment, with increasing cash generation and returns to shareholders.
Fundamental to this strategy is our focused high-return portfolio with Guyana and the Bakken as our growth engines where we plan to invest about 75% of our capital and exploratory expenditures over the next five years, and Malaysia and the deepwater Gulf of Mexico as our cash engines. Pro forma for our asset sales, our high-graded portfolio is on track to deliver capital-efficient compound annual production growth of approximately 10% through 2023 while driving cash unit costs down approximately 30% to less than $10 per BOE over the same period. The combination of growth and margin expansion is expected to drive compound annual cash flow growth of approximately 25% through 2023 at a $60 per barrel Brent oil price.
An integral part of our strategy is maintaining a strong balance sheet and liquidity position to ensure we have the financial capacity to fund our world-class investment opportunity in Guyana and maintain our investment grade credit rating. Our position in Guyana is truly world-class in every respect and transformational for our company. As of June, gross discovered recoverable resources for the Stabroek Block where Hess has a 30% interest and ExxonMobil is the operator have grown and are estimated to be more than 4 billion barrels of oil equivalent with multi-billion barrels of additional exploration potential.
In late August, we announced a ninth oil discovery on the block at the Hammerhead-1 well located approximately 13 miles southwest of the Liza-1 well, proving a new play concept for potential development. This month, a second exploration vessel, the Noble Tom Madden, arrived to accelerate exploration and appraisal activities on the block, starting with the Pluma prospect located 17 miles south of Turbot where we expect to spud in early November.
The Liza Phase 1 development which was sanctioned in June of last year is well-advanced with first production of gross 120,000 barrels of oil per day expected by early 2020. Phase 2 development with gross production of 220,000 barrels of oil per day is on track for startup by mid-2022. A third phase of development at the Payara Field is expected to have a gross production capacity of approximately 180,000 barrels of oil per day with first production in 2023. We now see the potential to produce on a gross basis more than 750,000 barrels of oil per day by 2025 with industry-leading returns and cost metrics.
Also key to our strategy is the Bakken where we have a premier acreage position and a robust inventory of high-return drilling locations with a significant infrastructure advantage. During the quarter we continued testing limited entry plug-and-perf completions and higher proppant loadings, and initial results are encouraging. In September we added a sixth rig and we expect to generate capital-efficient production growth of 15% to 20% per year through 2021 along with a meaningful increase in free cash flow generation over this period.
Now, turning to our financial results. In the third quarter we had net income of $52 million or $0.14 per share compared to a net loss of $624 million or $2.02 per share in the year ago quarter. On an adjusted basis, net income was $123 million or $0.38 per common share compared with an adjusted net loss of $324 million or $1.07 per common share in the third quarter of 2017. Compared to 2017, our improved third quarter financial results primarily reflect higher realized crude oil selling prices combined with lower operating costs and DD&A expense.
We had a strong operating performance across our portfolio. Third quarter production was above the high end of our guidance range, averaging 279,000 net barrels of oil equivalent per day, excluding Libya. Net production from Libya was 18,000 barrels of oil equivalent per day in the quarter. For full year 2018, we expect production to average approximately 255,000 net barrels of oil equivalent per day, excluding Libya, at the top end of our previous guidance of 245,000 to 255,000 net barrels of oil equivalent per day. In the fourth quarter, production is expected to average approximately 265,000 net barrels of oil equivalent per day, excluding Libya.
Third quarter net production in the Bakken averaged 118,000 barrels of oil equivalent per day compared to 103,000 barrels of oil equivalent per day in the year ago quarter. For the full year 2018, we continue to forecast that Bakken net production will average between 115,000 and 120,000 barrels of oil equivalent per day.
In summary, our reshaped portfolio is positioned to deliver a decade plus of capital efficient production growth with increasing cash generation and returns to shareholders. We look forward to providing a further update at our upcoming Investor Day on Wednesday, December 12 in Houston. I will now turn the call over to Greg for an operational update.
Thanks, John. I'd like to provide an update of our operational performance for the quarter as we continue to execute our strategy. In the third quarter, company-wide production averaged 279,000 net barrels of oil equivalent per day, excluding Libya. This was nearly 10% above the midpoint of our guidance range of 250,000 to 260,000 net barrels of oil equivalent per day for the quarter and reflects strong performance across our portfolio.
In the Bakken, production averaged 118,000 net barrels of oil equivalent per day, in line with our guidance for the quarter, and we drilled 34 wells and brought 29 new wells online. Consistent with previous guidance, we added a sixth Bakken rig and a third frac spread in the third quarter. For the fourth quarter, we forecast Bakken net production will increase to approximately 125,000 net barrels of oil equivalent per day; and we expect to drill approximately 35 wells and bring 31 wells online, bringing the total for full year 2018 to 120 wells drilled and 100 new wells brought online.
Average IP 180 for the year, which will be dominated by our 60-stage sliding sleeve completion design, is expected to exceed 125,000 barrels of oil, an increase of approximately 15% from full year 2017. We are also seeing encouraging results from our transition to limited entry plug-and-perf completions. Of the 100 gross operated wells we now expect to bring online this year, approximately 30 are planned to be plug-and-perf. We'll provide further details regarding these new high-intensity completions at our Investor Day in December.
On August 31 we closed on the sale of our JV interests in the Utica shale play to Ascent Resources for approximately $400 million. As a result of the sale, fourth quarter net production will be reduced by approximately 10,000 net barrels of oil equivalent per day relative to the third quarter.
Turning to the Gulf of Mexico. Net production came in well above guidance at 71,000 net barrels of oil equivalent per day, reflecting the return of production from the Conger Field in July, minimal weather-related downtime, and strong operating performance across all assets. As a result, we are raising our full year guidance to approximately 55,000 net barrels of oil equivalent per day. For the fourth quarter, we forecast Gulf of Mexico production to average approximately 65,000 net barrels of oil equivalent per day which includes 6,000 net barrels of oil equivalent per day of planned downtime primarily associated with an inspection of one of the risers at the Conger Field.
Now moving to the Gulf of Thailand. Production from our Asian assets averaged 68,000 net barrels of oil equivalent per day during the third quarter. At the joint development area in which Hess has a 50% interest, production averaged 37,000 net barrels of oil equivalent per day in the third quarter. Production is forecast to average approximately 36,000 net barrels of oil equivalent per day over the full year 2018. At the North Malay Basin, where Hess holds a 50% interest and is operator, production averaged 31,000 net barrels of oil equivalent per day in the third quarter which came in higher than expected due to a one-time rebalancing of entitlement volumes. Production is forecast to average approximately 26,000 net barrels of oil equivalent per day in 2018.
Company-wide, we forecast fourth quarter production to be approximately 265,000 net barrels of oil equivalent per day, excluding Libya. Strong year-to-date performance across our portfolio enables us to raise our full year guidance to approximately 255,000 net barrels of oil equivalent per day which is at the upper end of our previous guidance range of 245,000 to 255,000 net barrels of oil equivalent per day despite the loss of volumes associated with the sale of our Utica assets.
Now turning to Exploration. In August we announced our ninth discovery, Hammerhead, on the Stabroek Block offshore Guyana in which Hess holds a 30% interest and ExxonMobil is the operator. The well, which is located about 13 miles southwest of the Liza-1 discovery well, encountered 197 feet of high-quality, oil-bearing Miocene age sandstone reservoir, opening up a new play type. We recently completed a successful flow test and further appraisal activities are planned.
The Stenna Carron rig will now go to Las Palmas in the Canary Islands in Spain for recertification and is expected to return to the block in late December when we plan to spud a well on the upper Cretaceous Amara prospect located 24 miles southeast of the Turbot discovery. A second exploration vessel, the Noble Tom Madden drillship, has arrived in theater and is scheduled to spud a well on the Pluma prospect in early November. The well location is approximately 16 miles south of Turbot and will also target upper Cretaceous reservoirs on trend with the Turbot and Longtail discoveries.
In Suriname, Kosmos announced earlier this month that the Pontoenoe well on Block 42 in which Hess has a one-third interest failed to encounter commercial hydrocarbons and the well was expensed in the third quarter. The partners are studying the results of the well and will reprocess seismic to improve our understanding of the subsurface and regional geology. We continue to see multiple additional large prospects on the block which are independent from Pontoenoe and will be tested in 2020. In Canada, offshore Nova Scotia, BP continues drilling the Aspy play test well targeting a large subsalt structure analogous to those found in the Gulf of Mexico.
Moving to Guyana developments, Liza Phase 1 sanctioned in June 2017 remains on track for first oil by 2020 with a nameplate capacity of 120,000 barrels of oil per day. Liza Phase 2 is also on track for first oil by mid-2022 with a nameplate capacity of 220,000 barrels of oil per day. And finally, Phase 3 is currently in feed with first oil expected in 2023. The operator is focused on maximizing value through rapid, phased developments and accelerated exploration plans.
In closing, we have once again demonstrated strong execution and delivery and we are well-positioned to deliver significant value to our shareholders. I will now turn the call over to John Rielly.
Thanks, Greg. In my remarks today I will compare results from the third quarter of 2018 to the second quarter of 2018. For the third quarter of 2018 we had net income of $52 million compared with a net loss of $130 million in the second quarter of 2018. On an adjusted basis which excludes items affecting comparability of earnings between periods, we had net income of $123 million in the third quarter of 2018 compared with a net loss of $56 million in the previous quarter.
Turning to E&P. On an adjusted basis, E&P net income was $203 million in the third quarter of 2018 compared to $21 million in the second quarter of 2018. The changes in the after-tax components of adjusted E&P earnings between the third quarter and second quarter of 2018 were as follows. Higher sales volumes increased earnings by $146 million. Higher realized selling prices increased earnings by $65 million. Lower cash costs increased earnings by $12 million. Higher DD&A expense reduced earnings by $39 million. Higher exploration expense reduced earnings by $13 million. All other items increased earnings by $11 million for an overall increase in third quarter earnings of $182 million.
Turning to Midstream. The Midstream segment had net income of $30 million in both the third and second quarter of 2018. Midstream EBITDA before the non-controlling interest amounted to $130 million in the third quarter compared to $126 million in the previous quarter. For corporate, after-tax corporate and interest expenses were $122 million in the third quarter of 2018 compared to $191 million in the second quarter of 2018. After-tax adjusted corporate and interest expenses were $110 million in the third quarter of 2018 compared to $107 million in the previous quarter.
Turning to our financial position. Excluding Midstream, cash and cash equivalents were $2.6 billion, total liquidity was $7 billion including available committed credit facilities, and debt was $5.7 billion at September 30, 2018. Cash flow from operations before working capital changes and items affecting comparability was $738 million in the third quarter while cash expenditures for capital and investments were $566 million in the quarter. Changes in working capital reduced cash flows from operating activities by $258 million in the third quarter, reflecting premiums paid of $105 million on WTI crude oil hedging contracts for calendar 2019 and a payment of $84 million related to previously accrued legal claims associated with our former downstream interest. For calendar 2019, we have purchased WTI put options with a notional amount of 95,000 barrels of oil per day that have a monthly floor price of $60 per barrel.
In the third quarter we completed the sale of our joint venture interest in the Utica shale play for a net cash consideration of approximately $400 million. We also entered into a sale and leaseback agreement for a floating, storage and offloading vessel to handle produced condensate at our North Malay Basin project and received net proceeds of approximately $130 million. The gross lease obligation is reported as debt on our balance sheet and we will recover our partner share through future joint interest billings over the lease term.
In the third quarter we purchased $250 million of common stock, bringing total share repurchases under our previously announced $1.5 billion stock repurchase program to $1.25 billion. We plan to purchase the remaining $250 million in the fourth quarter.
Now turning to guidance. For E&P, in the third quarter our E&P cash costs were $11.41 per barrel of oil equivalent, including Libya, and $11.87 per barrel of oil equivalent, excluding Libya, which beat guidance on strong production and lower costs. On a pro forma basis, excluding Libya and Utica which was sold in August, cash costs in the third quarter were $12.20 per barrel of oil equivalent. We project cash costs for E&P operations, excluding Libya, in the fourth quarter to be in the range of $12.50 to $13.50 per barrel of oil equivalent which includes planned maintenance costs at the Conger Field in the Gulf of Mexico. Full year 2018 cash costs are expected to be $12.50 to $13.50 per barrel of oil equivalent which is down from previous guidance of $13 to $14 per barrel of oil equivalent.
DD&A expense in the third quarter was $16.14 per barrel of oil equivalent, including Libya, and $17.03 per barrel of oil equivalent, excluding Libya, which was below guidance. On a pro forma basis, excluding Libya and Utica, unit DD&A rates in the third quarter were $17.68 per barrel of oil equivalent. DD&A expense, excluding Libya, is forecast to be in the range of $18 to $19 per barrel of oil equivalent in the fourth quarter of 2018, and full year DD&A expense is projected to be $17 to $18 per barrel of oil equivalent which is down from previous guidance of $18 to $19 per barrel of oil equivalent. This results in projected total E&P unit operating costs, excluding Libya, of $30.50 to $32.50 per barrel of oil equivalent for the fourth quarter and $29.50 to $31.50 per barrel of oil equivalent for the full year of 2018.
Exploration expenses, excluding dry hole costs, are expected to be in the range of $55 million to $65 million in the fourth quarter with full year guidance expected to be in the range of $190 million to $200 million which is in the lower end of our previous guidance. The midstream tariff is projected to be approximately $170 million for the fourth quarter and approximately $655 million for the full year of 2018 which is up from previous guidance of approximately $635 million to $650 million. The E&P effective tax rate, excluding Libya, is expected to be a benefit in the range of 0% to 4% for the fourth quarter. The full year effective tax rate is expected to be a benefit in the range of 7% to 11% which is updated from the previous guidance of a benefit in the range of 16% to 20%.
For full year 2018, our E&P capital and exploratory expenditures guidance remains unchanged at $2.1 billion. Our 2018 crude oil hedge positions remain unchanged. We have $50 WTI put option contracts on a notional 115,000 barrels per day for the remainder of the year. We expect amortization of the premiums on these hedge contracts will reduce our financial results by approximately $50 million in the fourth quarter. For calendar 2019, we have purchased $60 WTI put option contracts with a notional amount of 95,000 barrels of oil per day for $116 million. We expect amortization of the calendar 2019 option premiums will reduce our financial results by approximately $29 million per quarter in 2019.
For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $30 million in the fourth quarter with the full year guidance of approximately $115 million remaining unchanged. For corporate, for the fourth quarter of 2018 corporate expenses are estimated to be in the range of $25 million to $30 million and for the full year guidance to be in the range of $100 million to $105 million which is in the lower end of our previous guidance. Interest expenses are estimated to be approximately $85 million in the fourth quarter and approximately $340 million for the full year of 2018 which is also at the low end of our previous guidance.
This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
Your first question comes from the line of Bob Morris from Citigroup. Your line is now open.
Thank you. Nice quarter, John.
Thank you.
Greg, on the Bakken you've got 35 wells still to drill here in the fourth quarter. Looks like you've added five plug-and-perf wells in the slate. Where are those wells spread out between the four different areas in Q4 and where are you primarily drilling the plug-and-perf wells between Keene, Stony Creek, East Nesson, and Capa?
Well, they're actually spread out in a number of areas across the field. I don't have the actual well numbers in front of me but it's really spread out over our whole position.
Okay. I didn't know if there was one area that sort of was left for the year end. So in the...
No.
...sixth rig that you just added, where was that put? What area?
That was put in the core.
In Keene or Stony Creek?
No, it was put in East Nesson.
East Nesson? Okay. And then I was going to ask about the continued outperformance at Stony Creek and Keene but I guess you'll give us an update on all that here in December.
I will absolutely at Investor Day.
Okay, great. That's all I had for now. Thanks.
Thank you. Your next question is from Doug Leggate from Bank of America. Your line is now open.
Thanks. Good morning.
Morning.
I wonder if I could hit a couple of questions on exploration in Guyana to start off. Greg, I realize that Guyana is probably going to be a focus on December 12, but I just wonder if you could touch on the visibility you have today. I want to reflect on comments you made back in August about potentially fast-tracking Hammerhead. That's not in the 750,000 barrels a day or the more than 750,000 barrels a day as I understand it. And similarly, the latest thoughts on the scale of Payara/Liza-3, and I've got a follow-up, please.
Okay, Doug. Well, first of all, Hammerhead, we just completed it at DST. Couple comments on Hammerhead to start. This is a massive accumulation. A very thick sand package. In fact, it's the thickest single sand package that we drilled on the block. It's a very large structure so it's going to require some additional appraisal. What we can say is that the results of the DST were good, meaning that the reservoir quality is excellent and the reservoir seems to be well-connected. You're right to say that Hammerhead's accretive to the 4 billion barrels and it could jump the queue in terms of being ahead of some of the other phases that were on the Turbot cluster, but it's too early to say that because we need some additional appraisal before we make that final decision. But, again, it is accretive to the 4 billion barrels. On the Payara cluster, as you mentioned, we're in feed. Right now, the vessel is sized at 180,000 barrels a day but that's still under discussion and will be part of the final project sanction towards the end of 2018.
Great. Thank you for that, Greg. And my follow-up on Guyana, if I may, is the exploration program. You mentioned the Amara prospect. I just want to be clear. Did that have another name? Was that Escolar (00:29:30) or is that something different? And if you could just give us an idea of where Ranger now fits in the queue because my understanding was (29:39) was going to go back to a Ranger appraisal at some point.
Yeah, Doug, you have a great memory. Amara is actually Escolar (00:29:48) or used to be called Escolar (00:29:49). Regarding the sequence of exploration and appraisal next year, that's still under discussion with the operator. We'll let you know once we get our budget finalized in 2019, but Ranger will be one of the things in the queue in 2019 obviously. But we've got some Hammerhead appraisal we want to do; there's some more work that we want to do in the Turbot area, so all that sequence is still being worked out.
Last one for me if I may, guys, is for the two Johns. And John Hess, I realize you've made your thoughts on share buybacks quite clear, but I guess I'm looking at the strength of the cash flow this quarter, the underlying cash flow. The demonstrable part of the portfolio obviously in this environment is pretty punchy. What is the right level of cash to carry on the balance sheet? And what's at the back of my mind really is you've got your preference issue maturing next year. I'm just wondering if there's a potential offsetting buyback that could dilute that or offset that dilution we're going to see next year, and I'll leave it there. Thanks.
Yeah. Doug, as you know, we are currently purchasing our stock under our current program. We constantly assess our allocation of capital. And as you know, we have been a leader among our peers in return of capital so we will continue to balance investing in our highest-return projects and returning capital to shareholders. That's our investment proposition and that's the path we've been following and we will continue to follow.
Great stuff. Appreciate the answers, guys. Thank you.
Thank you. Your next question comes from the line of Bob Brackett from Bernstein Research. Your line is now open.
Good morning. I understand you're probably not willing to talk too much about the 2019 program, but can you talk about the planning process and how you balance oil price uncertainty against the capital program and against building free cash flow?
Sure, Bob. So the first thing as you heard that we were looking at, we've always looked at 2019 again as with our bridge to Guyana coming in 2020 and we know we're investing in Phase 1 and now you know we're going to be also investing in Phase 2 and others, that the first thing we did, we put the 95,000 barrels a day of WTI put options in place. So watching oil volatility, we made sure we put a floor on that price for us for a good part of our production to ensure that we have that base cash flow. So we will, as you said, we'll be talking a lot more about this later on in our Investor Day. But while our budgeting process is underway, we're really excited about our capital and exploratory expenditure program through 2025. We think it's distinctive kind of as John Hess talked about earlier, that it'll deliver capital-efficient production growth that generates significant free cash flow over the period.
So just to be high level, talking about the activity levels that Greg was discussing, our 2019 budget will be closer to $3 billion. But it's important to note that all that incremental spend between 2018 and 2019 will be targeted, in our view, to the highest-return investments in the E&P business, and that's our Bakken and Guyana assets. And then just going longer-term, and again we'll give more detail on this, but maintaining our disciplined capital allocation, we currently expect capital and exploratory expenditures to average approximately $3 billion per year through 2025 and the portfolio to be cash-generative post-2020. And I would tell you, for now what we're looking at from a planning assumption case is using a $60 WTI and a $65 Brent. But, again, we'll provide more information later on in our Investor Day in December but, again, really excited about that.
Just specifically because Greg had mentioned it, what's going on in the Bakken, it's basically that incremental spend is almost half and half between the Bakken and Guyana. So in the Bakken we're going to be operating six rigs, that's 30% higher rig count than 2018, and right now probably approximately 50% more wells online in 2019 than 2018. So the vast majority also of those wells in 2019 are expected to be the higher-intensity plug-and-perf completions which currently carry an incremental cost of about $1.5 million per well versus our previous sliding sleeve design. But these wells are expected to deliver increases in both IP, rates, and more significantly in NPV. So it'll result in our Bakken production exceeding our previous guidance of 175,000 barrels per day by 2021.
Then in Guyana, we have the peak spend on Phase 1 in 2019. From our previous sanctioned release in 2019, it was about an $80 million increase in 2019 for Phase 1. And now you're going to see the commencement of spending for Phase 2. And remember, Phase 1, the initial year was $110 million so Phase 2 is obviously bigger than Phase 1, so you're going to see a little more spending for that. As well now feed costs for FPSOs 3 and 4 most likely and we are bringing the additional drill ship in, the Noble Tom Madden for next year. So that's kind of just high level. We'll go into more detail on it. But, again, from our overall program we're going to be generating significant free cash flow over the period because of these investments in Bakken and Guyana.
Great, appreciate the color. A quick follow-up. Adding that second exploration rig to Guyana, can you talk about how many wells you can get down in 2019 and how you'd split those across exploration of brand new concepts, exploration across the proven concepts, and then kind of appraisal/development?
Well, Bob, obviously it depends on what we find as we continue to explore the block. Again, that whole sequence hasn't been lined out yet with the operator but we know that we want to do some more appraisal in Hammerhead, so there will be some more there. We know we've got some more exploration/appraisal around Turbot. We know that we've got appraisal at Ranger. We know that we're going to drill this Hamira (00:36:28) well which could lead to more appraisal. And in addition to that, we have 20 additional prospects and leads that we'd like to drill on the block. So it's going to be a mix of exploration and appraisal and it really depends upon what we find as to how much appraisal we need. So we'll give you more color when we do our budget for 2019.
Thank you.
Thank you. Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is now open.
Thank you. Good morning.
Morning.
As we try to figure out the cash flow piece of the equation for next year, and we look specifically at the Gulf of Mexico where there was a nice step-up in production and it seems like maybe you're free and clear of some of the issues over the last year and a half, is 70,000 barrels a day or BOE a day the new normal when there's no downtime and how do you think about a more sustainable run rate of production and then the CapEx required to keep it there?
So what we've always said in the Gulf of Mexico is that kind of 65,000 barrels a day is a level of production that we can maintain here for several years because of the tieback opportunities that we have. So in 2019 we do have two rigs contracted, right, so we'll be completing the drilling and stampede with those two rigs. And then we talked about between signs of kind of like $100 million and $150 million that we spend every year just to do some tieback opportunities and hold that Gulf of Mexico production right around 65,000 barrels per day.
Got it, thank you. And then shifting to the Bakken, and I guess obviously we'll get more details shortly here in December, but to follow-up on the points you just made on the closer to $3 billion in 2019 CapEx overall, can you talk more on the Bakken specifically in terms of rig adds and then also expectations for well productivity/intensity and then also takeaway?
Okay. Let me let me take the first two and then John can talk about the takeaway. Certainly, our plan for next year is to hold six rigs flat. So we added that sixth rig in the third quarter and our plan is just to hold the rig count at six. As I mentioned, we're transitioning to a plug-and-perf completion, so that'll be a 10 million pound per well proppant loading that was confirmed as the optimum in the Bakken study. Just a few words about the Bakken study. Remember, that was an independent third party look that examined over 10,000 wells, both ours and our competitors, and the study confirmed a couple things. First of all, it confirmed that our use of sliding sleeves and tight spacing during the downturn maximized DSU NPV which has always been our objective, and then secondly that the transition to plug-and-perf in 2018 as a result of improving technology and lower costs in that space is the right strategy to deliver more value going forward.
And as John Rielly mentioned previously, the cost of those wells currently right now is running about $7.5 million per well, so about $1.5 million above the sliding sleeve completion. However, just as we did with the sliding sleeves, we begin to apply lean manufacturing to that process and we're reasonably confident that we can bring those well costs down over time as we apply lean manufacturing. But we will transition to that design over the remainder of 2018 and into 2019 on plug-and-perf. And, again, we'll give more color on that in our Investor Day in December.
Yeah. And, Brian, fair question. In terms of takeaway, our company does not have an issue in terms of takeaway capacity from the Bakken because of the pre-investment we've done to have access to multiple export markets, and that flexibility really positions us well to maximize the value of our sales netbacks. The recent widening in the Clearbrook differential began with October trading and is primarily the result of unusually high Mid-Continent refinery maintenance, not a takeaway issue, where that maintenance shut in more than 1 million barrels per day of refinery capacity. We expect this refinery demand to return in December with differentials narrowing towards historical levels. And our strategy of having these multiple export markets to maximize the value of our sales netbacks, recently in June when Clearbrook was a premium, was about $1 over WTI, we were actually maxing sales into the Clearbrook market. And in the current market, we are currently delivering about 70% of our crude to export markets where we receive Brent-based pricing which is about $6 over WTI. And in terms of the future, we're well-positioned now but we will continue to look at potential pipeline expansions as they may occur and may add additional firm transportation in the future to further optimize our marketing efforts.
Thank you very much.
Thank you. Your next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is now open.
Thanks. Good morning. Just curious on the comment on the Williston and the new plug-and-perf-focused program being able to deliver higher peak volumes relative to the prior 175 MBOE a day that you all had discussed. Any willingness to talk about what that new peak looks like and how long you can hold it? What sort of rig and annual completion cadence is required to do that?
No, we will talk about that at our Investor Day in December. But you're right. The peak is going to go up. Our current plan on the Bakken which, again, we'll cover on Investor Day is to take it to that new peak level, drop the rigs to four, and then hold it at that new peak level for a number of years. And, yeah, at that point the Bakken becomes a massive cash generator for the company, so cash flow will be significantly up in the Bakken. So as John Rielly mentioned, post-2020 you really have all of our assets generating free cash, significant amounts of free cash flow. And then of course, in 2022 when Phase 2 comes on, then Guyana becomes a major cash flow-generating asset. So you'll have all four assets generating significant amounts of cash when Phase 2 comes on.
Okay, that's helpful. How about how long you can hold that peak? Any commentary there at this point?
We'll, again, talk about that in December but it will be multiple years.
Okay. And then I guess maybe just on Suriname. Any additional color or commentary on what you guys have learned here post-mortem on the initial test? And it sounds like additional activity is not planned until 2020, but any spending that we should expect in 2019 as it relates to that asset?
I think first of all, the Pontoenoe well encountered 63 meters of really high-quality reservoir. Unfortunately it was wet, but now we're taking all that data from the well and we're going to recalibrate the seismic, rerun all the seismic, and that'll help inform future exploration in Suriname. But despite the dry hole, we still believe the block has significant resource potential as there's multiple play types on the block. So as you mentioned, current thinking is we won't get back to drilling until 2020 on the block and give us a good amount of time to reprocess things and understand what we saw.
Okay, great. That's helpful. Thanks.
Thank you. Your next question comes from the line of Arun Jayaram from JPMorgan. Your line is now open. Ajun (sic) [Arun] (00:45:43), your line is now open.
John, appreciate your comments on the Bakken takeaway where I think you are better positioned than your peers given your 50,000 barrels per day or so on DAPL, et cetera, and I think you only sell about 20% in the local markets today. My question is as we think about the incremental barrel that you produce in the Bakken, in our model we have you going from the mid-70s in oil to the low 90s in oil. So for those incremental barrels, where would you be selling those? Would they be on rail, et cetera? So just trying to understand what kind of diffs you could see on the incremental barrels that you're producing next year.
Good question, Arun. Our plan would be to continue to access Brent-based pricing between pipeline deliveries to the Gulf Coast and also rail deliveries either to the Gulf Coast, East Coast or West Coast.
Got it. Got it. And that's based on rail capacity that you have today or one or...?
Yes. Yeah, we're positioned for this now. And we'll also look at, as I said, potential pipeline expansions and may add additional firm transportation on those to ensure that we continue to optimize our differentials by getting access to offshore Brent-based pricing.
Okay. And I understand you guys are going to leave quite a bit for the Bakken for the December update. But the plan as I understand is to do about 50% more POPs are tied in line in the Bakken in 2019. Is that correct, like 150 wells or so?
Yes. Yes, you can make that assumption there with the six rigs at right around 150 and maybe a little bit more.
Got it. And my final question is, John, you mentioned that CapEx could approach $3 billion or so in 2019. Is that just in the E&P level or does that include with the consolidation of the Midstream the Midstream piece of that as well? Or if you could separate the two, that would be helpful.
That's the E&P portion and includes the spend for exploration as well. So that's just that E&P, yeah.
Okay. Thanks a lot.
Sure.
Thank you. Your next question comes from the line of Paul Cheng from Barclays. Your line is now open.
Hey, guys. Good morning.
Morning.
Two quick questions. John, on the well capacity, can you tell us how much you plan to ship from Bakken in the fourth quarter? And also, we've heard from people saying that the well operator that they are unwilling to increase the (00:48:35) unless you are willing to sign multiple year contract. Is that what you, guys, are seeing?
In terms of takeaway capacity, right now, I mentioned it before, it's about 70% of our crude is going to export markets where we can receive Brent-based spot pricing, most of it on DAPL, out to Nederland, and then some to both the East Coast and West Coast via train. And in terms of going forward, there are multiple pipeline expansion opportunities. We're looking at them and the terms and conditions of those vary.
Can you share with us that? I mean, how much is the cost for you to move from Bakken to the East Coast if you're going to (00:49:25)?
Well, I tell you, what I would say is going down south to Nederland is about $7. And train's a little bit higher than that, West Coast being closer to that number, East Coast being a little higher.
Okay. Thank you.
Thank you. Your next question comes from the line of Roger Read from Wells Fargo. Your line is now open.
Read, Read, whatever it needs to be today I guess. Good morning, guys.
How you doing?
Doing all right, thanks. Just one thing I'd like to follow up on on the CapEx side, the move from kind of $2.1 billion, $2.2 billion this year to $3 billion overall. You mention kind of half between the Bakken and half between Guyana. Since we had obviously a little spending on Utica and maybe some other places this year, kind of what's the right increment? Is that to think about it as $900 million and $450 million, $450 million or it's a larger number as the starting point is slightly different? And then maybe other way to think about it is does exploration spending go up from here relative to what we've seen which I would think has to happen given a second rig in Guyana and then potential in 2020 to restart in Suriname? So maybe just a little clarity on that if you could.
Sure. So first, outside like you said Utica or assets like that, we were not spending much capital in 2018 on that. So the base that you should start with is the $2.1 billion because our capital guidance remains unchanged, and so then moving up, I'd say, going to that, closer to $3 billion. There's a little bit more going to Bakken than Guyana. And if you can just – I'll do some simple math for you. Bakken guidance was approximately $900 million for this year. We're about at 4.75 rigs and we're going to six rigs for the full year. On average we're 4.75 rigs. Just do the math on that, you'll get about $240 million just with everything being exactly the same.
Then as Greg and I had mentioned, the current plug-and-perf wells are approximately $1.5 million higher. We're going to be drilling a lot more of them next year than we did this year. So just simply, if you took that 150 times $1.5 million, put our working interests around 80% or so in it, you can kind of see how you're getting to the numbers there in the Bakken. So it's simply like that. And then Guyana, it's exactly what I talked about before. It's just the additional drill ship. That factors in for exploration. So when I was talking about Guyana, that included this additional exploration spend from that additional drill ship.
Yeah. And, Roger, just again to, I'd say, reemphasize the point that John made earlier, the increment in CapEx is going to very high-return projects, the increment being probably in the range of 30% to 50% IRRs, very quick paybacks. While next year we'll ramp up in CapEx, we should start becoming cash flow-positive in a $60 WTI, $65 Brent world. In 2020, covering the CapEx and dividend, we should become cash flow-generative there. And then the outlook going past that, and we'll go over this at Investor Day, is that CapEx going forward probably is going to be in the range of $3 billion, holding flat out to 2025. So our portfolio becomes very cash-generative, putting us in a great position to balance investing in the business in the high returns going forward and also returning capital to our shareholders.
That's great clarity. Thank you.
Thank you. Our next question is from Jeffrey Campbell from Tuohy Brothers. Your line is now open.
Good morning.
Morning.
I wanted to just ask a quick question regarding the expectations for the Pluma exploration well that you mentioned in the press release. And I'm really asking this because I'm trying to get some sort of a feel for how the hubs are going to develop. If it was successful, would it more likely be a tie-in to Turbot or could it potentially support stand-alone production?
No, I think it'll be part of that what we call the greater Turbot complex. We're really trying to define that to understand how many vessels it's going to take to evacuate that, right, that area. There's a lot of accumulations there that we want to get a drill bit in.
Okay. No, that's helpful. Thank you. And I just wanted a quick question, just a little color on the improved Bakken well performance that was mentioned in the press release. I was just wondering is there anything new going on at the completion candidate or was this just an example of exceeding prior expectations?
No, I think it's just continuous improvement in completion practices. That number that I gave you is primarily dominated by sliding sleeves fleet. So recall this year we increased the proppant loading in our 60-stage sliding sleeves to 140,000 pounds per stage, so that's about 8.4 million pounds on the sliding sleeve. So primarily that number I gave you reflects that increase in proppant in sliding sleeves. In addition to that, we're also transitioning to plug-and-perf. And based on the results of the Bakken study and some of the very preliminary results that we got from our early plug-and-perf trials, that move to 10 million pounds is going to be very value-accretive. So we'll give you some more color on that in December but that'll be to – the first jump was sliding sleeve move, the next jump will be plug-and-perf, and you'll get an increment on each of those.
Okay, great. Yeah, that's very helpful and I look forward to the Analyst Day in December. Thank you.
You bet.
Thank you. Our next question is from Paul Sankey from Mizuho. Your line is open.
Hi everyone.
Hi.
Actually, John Hess just hit the nail on the head I was going to ask about the run rate of CapEx given next year's number, but you clearly answered that one so thank you there. Maybe I could ask on DD&A coming down. Could you give the outlook for that dynamic, what caused it to come in below expectations, and what do you think the outlook is there? Thank you.
And, Paul, before John Rielly answers it, I understand congratulations are in order for your marriage. So I want to get that out first.
I appreciate that, John. Thank you very much indeed.
Paul, the DD&A in the third quarter, really, the better performance in guidance was due to the production. So what we had was that higher production in the Gulf of Mexico with lower DD&A, and so that's what's driving that third quarter DD&A rate down. And then on a go-forward basis, as we project into the future kind of what John was talking about with always our capital being focused in those high-return Bakken and Guyana assets, we continue to see over this period through 2025 that our DD&A rate will continue to come down, and we'll give more information on that on the Investor Day.
Great. Thank you, gentlemen.
Thank you. Your next question comes from the line of Pavel Molchanov from Raymond James. Your line is now open.
Thanks for taking the question. It seems like every week now there is a parent company that is taking back and acquiring its MLP. In that context, I thought I would get your thoughts on how committed you are and Global Infrastructure Partners is to maintaining Hess Midstream as a stand-alone public entity.
Yeah. I mean, it hasn't been that long since we've done the IPO of the Midstream. And the Midstream has been performing fantastically and it's been a great partner for us in this build-out of infrastructure. And as we're going to talk about obviously moving to the plug-and-perf and our increasing production above the 175,000 barrels per day, having that midstream partner, GIP, and Hess Midstream overall will really help us in that. And as John had mentioned before in our takeaway capacity, it's really just in general put us in a great place from a revenue standpoint and a cost standpoint. So where we are with that? I know what you've been talking about. We've been watching that happen in the market but it's early days. We've got plenty of growth left in that public midstream vehicle that we have. We're happy with its performance and expect it to continue to perform well.
And one question about Guyana that – you'll maybe hold off on this until the Analyst Day, but you're very close to approving Phase 2. You're talking about five total. For a country as small as Guyana, and that has never had an oil industry, are you facing any labor shortages or other kinds of bottlenecks as you're creating essentially a brand new value chain where none has existed before?
No. So far there's no issues with labor shortage. Remember, this is an offshore development so the majority of everything is floated in, right, and the work is all done offshore. And I think ExxonMobil as operator has done a great job in maximizing local content where possible.
All right. Appreciate it, guys.
Thank you. Your next question comes from the line of Doug Leggate from Bank of America. Your line is now open.
Hey, guys. Sorry for lining up again. I just wanted to clarify something on the capital program. So, John Rielly, I know you don't want to give details on the Guyana fiscal contract. But exploration costs on the entire block as I understand it can be recovered from any revenue? Is that still the case? In which case, once you've got first oil what can you say about the cost recovery on the exploration dollars?
The contract works as the whole block is the ring fence, so all costs can be recovered once production starts. So you are correct in what you said.
And that applies to development dollars on subsequent phases as well?
Yes, it does.
Great stuff, thank you. And just one final quick one on the MLP given that question just got asked. Is your plan still to monetize units on the MLP over time?
We are committed to the MLP and we don't have the need as Hess to monetize anything right now and neither does GIP because basically the drop-downs from Hess is going to Midstream Partners and we have a multi-year runway where we don't need to do any drop-downs into the MLP, so I just want to be clear. And I also want to be clear that Hess and GIP are committed to the MLP and continuing the growth trajectory and really maximizing value from our investment in the Midstream business.
Great. Thanks, guys.
Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.